Field
The present disclosure relates to techniques for measuring multiphase flows in wellbores. More particularly, the present disclosure relates to tools and methods for intelligent completions and monitoring systems, including monitoring multiphase fluid flow in wellbores.
Description of the Related Art
Exploring, drilling and completing hydrocarbon and other wells are generally complicated, time consuming and ultimately very expensive endeavors. In recognition of the potentially enormous expense of well completion, added emphasis has been placed on well monitoring and maintenance throughout the life of the well. Increasing the life and productivity of a given well may help ensure that the well provides a healthy return on the significant investment involved in its completion. Thus, over the years, well diagnostics and treatment have become more sophisticated and critical facets of managing well operations.
In certain circumstances, well diagnostics takes place on a near-continuous basis such as where pressure, temperature or other sensors are disposed downhole, for example, in conjunction with production tubing. A monitoring tool with sensors may be affixed downhole with tubing in order to track well conditions during hydrocarbon recovery. In some cases, the monitoring tools may be fairly sophisticated with capacity to simultaneously track a host of well conditions in real time. Thus, both sudden production profile changes and more gradual production changes over time may be accurately monitored. Such monitoring allows for informed interventions or other adjustments where appropriate. By the same token, these types of conditions may be monitored in conjunction with an intervention such as a logging application as opposed to relying on permanently installed downhole components.
Whether permanently installed or introduced with other interventional equipment, monitoring tools may be equipped with flowmeters in order to keep track of downhole fluid flow. For example, monitoring of downhole fluid flow may be a fairly direct indicator of the hydrocarbon recovery rate for a given well. The flowmeter itself is often a Venturi flowmeter which introduces a bottleneck-type of restriction to the flow of fluid resulting in measurable differential pressure data. This data may be used to ascertain fluid flowrate and to indirectly estimate density.
Unfortunately, there are certain limitations to using Venturi flowmeters to ascertain flowrate in a well. For example, the flowrate is not directly measured. Instead, it is estimated based on the relationship between the pressure drop induced by a constriction and the product of density and the square of the volumetric flowrate. As a result, the computation introduces a certain degree of inherent inaccuracy because of a direct measurement, a pressure drop from differential pressure measurements is correlated to the square of flowrate. Thus, even a minor inaccuracy in a pressure measurement may be amplified when translated to flowrate. Once more, the range of flowrate detectable by such a flowmeter is also limited due to the indirect nature of the meter. The need to correlate pressure to a square of the flowrate means that the flowrate needs to be within a manageable window in order to ensure practical correlation to detected pressure.
In light of the limitations on venturi flowmeters, vortex flowmeters are often utilized. A vortex flowmeter is capable of taking more direct measurements of flowrate through inducing and monitoring vortices. More specifically, instead of introducing a restriction or bottlenecking type of feature to a flow of fluid, a vortex flowmeter introduces a bluff body to a flow of fluid. A bluff body is an elongated structure that traverses a flow of fluid in a channel and is of a shape that is configured to encourage the formation of vortices. As the flow meets a generally flat surface face of the stationary bluff body, vortices of swirling fluid will form in a regular pattern and continue on downstream for a period, eventually attenuating. This regular pattern of vortices will take place at a frequency that is directly related to the flowrate of the flowing fluid. As a result, sensors positioned immediately adjacent and downstream of the face of the bluff body to detect the frequency of the forming vortices may provide flowrate information. Acoustic sensors, pressure sensors, and other sensors may be used to acquire such vortex frequency information.
Because the vortex flowmeter provides a more direct measurement of flowrate, accuracy may be improved. Similarly, the direct measurement also means that the range of detections is not limited based on the need to keep values within a practical window for sake of calculations. Thus, in theory, a vortex flowmeter may provide greater accuracy and range than a Venturi flowmeter.
Unfortunately, the vortex flowmeter is not able to provide usable detections where the fluid type changes from one type to another. For example, it is not uncommon in a well for a hydrocarbon liquid to transition to a gas or for water to emerge in the fluid stream. When this type of phase change occurs, the uniform vortices are interrupted by perturbations that are not detectable in an understandable manner by the sensors at the bluff body and instead of detecting flowrate, no detection at all may occur even where the flowrate has not changed. Thus, as a practical matter, operators are often left with only the option of utilizing a less accurate, narrower range flowrate detector as opposed to risking no detection at all.